Quaternary Ammonium Emulsion Breakers

ABSTRACT

A method may include: performing a treatment operation on at least a portion of a subterranean formation using an oil-in-water emulsion treatment fluid that comprises an oleaginous phase and an aqueous phase; recovering at least a portion of the oil-in-water emulsion treatment fluid from the portion of the subterranean formation; introducing a quaternary ammonium compound into the recovered portion of the oil-in-water emulsion treatment fluid at a well site; and mechanically separating at least a portion of the recovered portion of the oil-in-water emulsion treatment fluid into an oleaginous fluid and an aqueous fluid

CROSS-REFERENCE TO RELATED APPLICATION

The present application claims the benefit of U.S. ProvisionalApplication No. 62/714,445 filed Aug. 3, 2018, which is incorporatedherein by reference in its entirety for all purposes.

BACKGROUND

The present disclosure relates to systems and methods for use insubterranean formations. Hydrocarbons, such as oil and gas, are commonlyobtained from subterranean formations that may be located onshore oroffshore. The development of subterranean operations and the processesinvolved in removing hydrocarbons from a subterranean formationtypically involve a number of different steps such as, for example,drilling a wellbore at a desired well site, treating the wellbore tooptimize production of hydrocarbons, and performing the necessary stepsto produce and process the hydrocarbons from the subterranean formation.

Treatment fluids are used in a variety of operations that may beperformed in subterranean formations. As referred to herein, the term“treatment fluid” will be understood to mean any fluid that may be usedin a subterranean application in conjunction with a desired functionand/or for a desired purpose. The term “treatment fluid” does not implyany particular action by the fluid. Treatment fluids often are used in,e.g., well drilling, completion, and stimulation operations. Examples ofsuch treatment fluids include, inter alia, drilling fluids, well cleanupfluids, workover fluids, conformance fluids, cementing fluids, gravelpack fluids, acidizing fluids, fracturing fluids, spacer fluids, and thelike.

During the drilling of a wellbore into a subterranean formation, adrilling fluid, also referred to as a drilling mud, may be continuouslycirculated from the surface down to the bottom of the wellbore beingdrilled and back to the surface again. Among other functions, thedrilling fluid serves to transport wellbore cuttings up to the surface,cool the drill bit, and provide hydrostatic pressure on the walls of thedrilled wellbore. Drilling fluids generally may be water-based oroil-based and synthetic-based fluids. One type of water-based fluid maybe an oil-in-water emulsion that includes an aqueous continuous phaseand an oleaginous discontinuous phase. To avoid the loss of the drillingfluid and allow its reuse, the cuttings may be separated from thedrilling fluid at the surface. A variety of different solids separationequipment may be used at the well site, including shale shakers,demanders, desalter, mud cleaners, centrifuges, and the like. Afterremoval of the drilling cuttings, the recovered drilling fluid may bereused in the wellbore, or the oil or water in the drilling fluidrecycled for reuse, for example, in another treatment fluid.

BRIEF DESCRIPTION OF THE DRAWINGS

These drawings illustrate certain aspects of some of the embodiments ofthe present disclosure, and should not be used to limit or define theclaims.

FIG. 1 is a diagram illustrating an example of a drilling assembly thatmay be used in accordance with certain embodiments of the presentdisclosure.

FIG. 2 is a schematic diagram illustrating oil recovery results obtainedfor the emulsion breaking of field mud samples in accordance withcertain embodiments of the present disclosure.

While embodiments of this disclosure have been depicted, suchembodiments do not imply a limitation on the disclosure, and no suchlimitation should be inferred. The subject matter disclosed is capableof considerable modification, alteration, and equivalents in form andfunction, as will occur to those skilled in the pertinent art and havingthe benefit of this disclosure. The depicted and described embodimentsof this disclosure are examples only, and not exhaustive of the scope ofthe disclosure.

DESCRIPTION OF CERTAIN EMBODIMENTS

Illustrative embodiments of the present disclosure are described indetail herein. In the interest of clarity, not all features of an actualimplementation are described in this specification. It will of course beappreciated that in the development of any such actual embodiment,numerous implementation specific decisions must be made to achievedevelopers' specific goals, such as compliance with system related andbusiness related constraints, which will vary from one implementation toanother. Moreover, it will be appreciated that such a development effortmight be complex and time consuming but would nevertheless be a routineundertaking for those of ordinary skill in the art having the benefit ofthe present disclosure. Furthermore, in no way should the followingexamples be read to limit, or define, the scope of the disclosure.

As used herein, a “hydrocarbon chain” may, unless otherwise specificallynoted, be branched, unbranched, non-cyclic, and/or cyclic; it may besubstituted or unsubstituted (that is, it may or may not contain one ormore additional moieties or functional groups in place of one or morehydrogen atoms in the hydrocarbon chain); and/or it may be saturated orunsaturated. Furthermore, as used herein, the nomenclature “C_(x) toC_(y)” refers to the number of carbon atoms in the hydrocarbon chain(here, ranging from x to y carbon atoms). As used herein.“independently” refers to the notion that the preceding items may be thesame or different.

The present disclosure relates to systems and methods for use insubterranean formations. Particularly, the present disclosure relates tocompositions and methods for the use of quaternary ammonium compounds tobreak oil-in-water emulsion treatment fluids.

In some embodiments, the present disclosure may include a methodincluding introducing a quaternary ammonium compound into anoil-in-water emulsion treatment fluid that comprises an oleaginous phaseand an aqueous phase and centrifuging at least the portion of theoil-in-water emulsion treatment fluid to separate at least a portion ofthe oil-in-water emulsion treatment fluid into an oleaginous fluid andan aqueous fluid. In certain embodiments, the methods of the presentdisclosure may include performing a treatment operation on at least aportion of a subterranean formation using an oil-in-water emulsiontreatment fluid that comprises an oleaginous phase and an aqueous phase;recovering a least a portion of the oil-in-water emulsion treatmentfluid from the portion of the subterranean formation; introducing aquaternary ammonium compound into the recovered portion of theoil-in-water emulsion treatment fluid at a well site; and mechanicallyseparating at least a portion of the recovered portion of theoil-in-water emulsion treatment fluid into an oleaginous fluid and anaqueous fluid.

In some embodiments, the methods of the present disclosure may includeintroducing a quaternary ammonium compound into an oil-in-water emulsiontreatment fluid; introducing a brine into the oil-in-water emulsiontreatment fluid; heating the oil-in-water emulsion treatment fluid to atleast 80° F.; and mechanically separating at least a portion of theoil-in-water emulsion-treatment fluid into an oleaginous fluid and anaqueous fluid.

Among the many potential advantages to the methods and compositions ofthe present disclosure, only some of which are alluded to herein, themethods, compositions, and systems of the present disclosure may provideimproved and more effective means to break oil-in-water emulsion fluids.In certain embodiments, the methods, compositions, and systems of thepresent disclosure may reduce the volume of waste at a job site. In someembodiments, this may, among other benefits, reduce the costs associatedwith transporting untreated fluids off-site for treatment and/ordisposal. In some embodiments, the methods and systems of the presentdisclosure also may increase the amount of aqueous or non-aqueous fluidsavailable for reuse in subsequent subterranean operations. In someembodiments, this may, among other benefits, reduce the amounts and/orconcentrations of contaminants in fluids sufficiently to re-use thefluids in subsequent operations (e.g., fracturing operations, drillingoperations, etc.) at the same well site or job site where it wasrecovered or at another site. In some embodiments, this may reduce oreliminate the cost associated with transporting fluids to the well siteor job site for such operations.

In certain embodiments, the quaternary ammonium compound may beintroduced into an oil-in-water emulsion treatment fluid. In someembodiments, the quaternary ammonium compound and the oil-in-wateremulsion treatment fluid are mixed to allow the oil-in-water emulsiontreatment fluid to at least partially separate before centrifugingand/or another mechanical treatment is applied to the fluid. In certainembodiments, the quaternary ammonium compound may be a fatty alkylquaternary ammonium compound. In certain embodiments, the quaternaryammonium compound may be substantially of the formula R¹R²R₃R⁴N⁺.

In some embodiments, each of R¹, R², and R³ may independently be a C₁ toC₁₀ hydrocarbyl group. In some embodiments, at least one of R¹, R², andR₃ may include a C₁ to C₁₀ hydrocarbon chain. The hydrocarbon chain mayinclude any one or more hydrocarbon groups selected from the groupconsisting of: alkyl, alkenyl, alkynyl, aryl, arylalkyl, arylalkenyl,alkylaryl, alkenylaryl, and any combination thereof, for example. Incertain embodiments, any one or more of R¹, R², and R¹ may be branched,unbranched, non-cyclic, cyclic, saturated, and/or unsaturated. Incertain embodiments, each of R¹, R², and R¹ may independently include(i) as few as any one of: 1, 2, 3, 4, 5, 6, 7, 8, 9, and 10 carbonatoms, and (ii) as many as one of: 2, 3, 4. 5, 6, 7, 8, 9, and 10 carbonatoms. For example, suitable ranges of numbers of carbon atoms in eachof R¹, R², and R³ according to various embodiments include, but are notlimited to 1 to 2, 1 to 3, 1 to 4, 1 to 5, 1 to 6, 1 to 7, 1 to 8, 1 to9, 1 to 10, 2 to 4, 3 to 5, 4 to 6, 5 to 7, 6 to 8, 7 to 9, 8 to 10, andthe like.

In some embodiments, any one or more of R¹, R², and R³ may include a C₁to C₁₀ alkyl chain. In some embodiments, any one or more of R¹, R², andR³ may include a C₂ to C₆ alkenyl or alkynyl chain. In some embodiments,any one or more of R¹, R², and R³ may include a C₃ to C₆ cyclic moiety.In certain embodiments, any one or more of R¹, R², and R³ may besubstituted (e.g., it may include any one or more functional groups inaddition to the hydrocarbon groups described above). In certainembodiments, at least one of R¹, R², and R³ may include a heteroatom(e.g., may include O, N, P, S, or another atom other than C or H).

In certain embodiments, R⁴ may include a hydrocarbon chain, for example,a fatty alkyl chain. Examples of hydrocarbon chains suitable for certainembodiments of the present disclosure include, but are not limited toalkyl chains in the range of from about 1 to about 18 carbon atoms, fromabout 8 to about 18 carbon atoms, from about 12 to about 16 carbonatoms, or from about 12 to about 14 carbon atoms. In some embodiments,R⁴ may include a hydrophilic moiety. In certain embodiments, R⁴ includesa hydrocarbon chain and a hydrophilic moiety. Examples of hydrophilicmoieties suitable for certain embodiments of the present disclosureinclude, but are not limited to a carboxylic acid, an ester, a glycol,an ethylene glycol, an ether, an amine, a sulfonamide, an amide, aketone, a carbonyl, an isocyanate, a urea, a urethane, any derivative ofthe foregoing, and any combination thereof. In some embodiments, thequaternary ammonium compound includes a fatty carboxylic acid chain.

In certain embodiments, the quaternary ammonium compound may includeand/or be bonded to a polymer moiety. In some embodiments, thequaternary ammonium compounds may include water-soluble cationiccopolymers including a quaternary moiety. In some embodiments, thequaternary ammonium compounds may be derived from acrylamide and aquaternary compound of diallylamine. In certain embodiments, thequaternary ammonium compound may include an ethylene oxide quaternarycopolymer. In some embodiments, the quaternary ammonium compound may bea non-polymeric compound and/or may not include a polymeric moiety. Insome embodiments, the quaternary ammonium compound may be substantiallyfree, or entirely free, of polymers.

In certain embodiments, the quaternary ammonium compound may be tethered(e.g., bonded or attached) to a nanoparticle. Nanoparticles suitable forcertain embodiments of the present disclosure include, but are notlimited to silver nanoparticles, gold nanoparticles, coppernanoparticles, and any combination thereof. In certain embodiments, thenanoparticles may include particles having a diameter of 100 nm orsmaller, 10 nm or smaller, or 1 nm or smaller. In some embodiments, thenanoparticles may include particles having a diameter of from about 0.1nm to about 100 nm. In certain embodiments, the nanoparticles mayexhibit a particle size distribution between about 0.1 nm and about 100nm. For example, in some embodiments, the plurality of nanoparticles mayhave a d50 particle size distribution of from about 0.1 nm to about 100nm. In certain embodiments, the plurality of nanoparticles may exhibit ad50 particle size distribution of 100 nm or smaller, 10 nm or smaller,or 1 nm or smaller.

In certain embodiments, one or more quaternary ammonium compounds may beintroduced into and/or be present in an oil-in-water emulsion treatmentfluid in an amount within a range of from about 0.1% to about 10% basedon the volume of the oil-in-water emulsion treatment fluid. In someembodiments, an effective amount of one or more quaternary ammoniumcompounds for breaking and/or separating the oil-in-water emulsiontreatment fluid may be as low as any of: 0.1, 0.5. 1, 1.5, 2, 2.5, 3,3.5, 4, 4.5, 5, 5.5, 6. 6.5, and 7%, based on the volume of theoil-in-water emulsion treatment fluid, in certain embodiments, aneffective amount of one or more quaternary ammonium compounds forbreaking and/or separating the oil-in-water emulsion treatment fluid maybe as high as any of: 3.5, 4, 4.5, 5, 5.5, 6, 6.5, 7, 7.5, 8, 8.5, 9,9.5, and 10%, based on the volume of the oil-in-water emulsion treatmentfluid. Thus, in some embodiments, an effective amount of quaternaryammonium compounds may be within a range of from about 1% to about 5%based on the volume of the oil-in-water emulsion treatment fluid; fromabout 0.1% to about 5% based on the volume of the oil-in-water emulsiontreatment fluid; from about 0.1% to about 10% based on the volume of theoil-in-water emulsion treatment fluid; or from about 0.5% to about 10%based on the volume of the oil-in-water emulsion treatment fluid. Itfurther will be appreciated by one of ordinary skill in the art havingthe benefit of the present disclosure that the amount of the quaternaryammonium compound effective tor breaking and/or separating theoil-in-water emulsion treatment fluid may depend upon, for example, thetemperature, pressure, fluid composition, other additives in the fluid,and other conditions.

In certain embodiments, the quaternary ammonium compounds may act asdemulsifiers to break oil-in-water emulsion drilling fluids. In someembodiments, at least 50% of the treatment fluid by volume may includethe oil-in-water emulsion. The oil-in-water emulsion treatment fluid mayinclude an aqueous phase and an oleaginous phase. In certainembodiments, the aqueous phase may include fresh water, seawater, or abrine. Examples of oils suitable for certain embodiments of theoleaginous phase of the present disclosure include, but are not limitedto diesel oil, diesel-like oils, mineral oils, unsaturated olefins,organic esters, and any combination thereof. The oil-in-water emulsionof the present disclosure may include oil in any suitable proportion ofthe emulsion as will be appreciated by one of skill in the art with thebenefit of this disclosure. In certain embodiments, the oil may bepresent in the emulsion in an amount from about 0.01% to about 50% byvolume of the emulsion. In other embodiments, the oil may be present inthe emulsion in an amount from about 10% to about 40% by volume of theemulsion.

In other embodiments, the oil may be present in the emulsion in anamount from about 20% to about 30% by volume of the emulsion.

In certain embodiments, the quaternary ammonium compounds of the presentdisclosure may be provided, used, and/or introduced as a salt of one ormore of the compounds described herein. In such embodiments, the saltmay include one or more counter anions. For example, the quaternaryammonium compound discussed herein may be present as a salt with acounter anion. In certain embodiments, such salts may wholly orpartially dissociate in aqueous solution. In other embodiments, thesalts may remain substantially associated (either with the originalanion or with other ions from solution). Counter anions suitable forcertain embodiments of the present disclosure include, but are notlimited to a carboxylate, a halide, a sulfate, a nitrate, an organicsulfonate, a hydroxide, and/or any combination thereof. It will beappreciated by one of ordinary skill in the art having the benefit ofthis disclosure that salts may be formed with other counter anionsinstead of or in addition to the counter anions specifically disclosedherein. In some embodiments, the anion of the salt may be selectedbased, at least in part, on the cost and/or availability of anions.

In some embodiments, the quaternary ammonium compound may be introducedalong with a solvent (along with other optional components). In certainembodiments, the quaternary ammonium compound may be mixed with asolvent prior to introduction into the oil-in-water emulsion treatmentfluid. In certain embodiments, the solvent may include one or moreorganic solvents. Examples of solvents suitable for certain embodimentsof the present disclosure include, but are not limited to an alcohol,methanol, ethanol, isopropyl alcohol, glycol, a glycol ether, anyorganic solvent, toluene, xylene, monobutyl ether, hexane, cyclohexane,and/or any combination thereof. In certain embodiments, the quaternaryammonium compound is added to a fluid as an emulsion breaker additivethat includes the quaternary ammonium compound and a solvent. In someembodiments, the emulsion breaker additives may include NO BLOK® C, aquaternary ammonium compound and an isopropyl alcohol solvent, availablefrom Halliburton Energy Services, Inc.

In some embodiments, the methods of the present disclosure may includeintroducing a brine into the oil-in-water emulsion treatment fluid. Incertain embodiments, the brine may dilute the oil-in-water emulsiontreatment fluid. The brine may be co-introduced with the quaternaryammonium compound or introduced separately. In certain embodiments, thebrine may include an aqueous saturated salt solution. In certainembodiments, the brine may be any monovalent brine. In certainembodiments, the brine may be a saturated monovalent salt brine. Forexample, in some embodiments, the brine may be a saturated sodium brine.In some embodiments, the brine and quaternary ammonium compound may bemixed together to form an additive solution including the quaternaryammonium compound, and the additive solution may be introduced into theoil-in-water emulsion treatment fluid.

In certain embodiments, the quaternary ammonium compounds of the presentdisclosure may provide effective emulsion breaking for oil-in-wateremulsion treatment fluids with an aqueous phase having a pH1 in a rangeof from about 5 to about 12, from about 6 to about 12, or from about 6to about 10.

Some embodiments of the present disclosure may include a treatmentsystem for performing the system and methods of the present disclosure.In some embodiments, the treatment system may include one or morechemical and/or mechanical treatment subsystems, which may include anyvessels (e.g., tanks), conduits, or other devices suitable forconducting those treatments, and may be of any suitable shape and sizefor holding and/or treating treatment fluids. In some embodiments, thetreatment systems of the present disclosure may be located, and thetreatment methods may be performed, on an offshore rig or ship that isengaged in offshore subterranean operations, such as a drilling rig ordrill ship. In other embodiments, the treatment systems may be located,and the treatment methods may be performed, at a land-based job site.The various components of the treatment systems discussed herein, aswell as any other components of those systems, may be housed together ina single unit, or may be provided as one or more separate modules ortanks that may be connected and/or otherwise used together to performdifferent portions of the treatment process.

In some embodiments, the vessels in these subsystems may include a tank.The tank may include one or more inlets through which treatment fluidsmay flow into the tank, and one or more outlets through which fluids maybe released. Any suitable valves, pumps, or other devices may be usedfor controlling the flow of water through the inlets and/or outlets ofthe tank. In some embodiments, the tank may be equipped with one or moreagitation devices such as rotary stirring rods, paddles, blades, airnozzles, etc. that are configured to stir, mix, and/or agitate thecontents of the tank and, in some embodiments, promote the breaking ofoil-in-water emulsion treatment fluids in the tank.

In some embodiments, these vessels and/or conduits also may be equippedwith arrays of sensors for detecting various types of phenomena (e.g.,condition of certain equipment therein, flow of fluids, etc.) orproperties of a fluid in the vessel and/or conduit. In some embodiments,the chemical treatment subsystems may include one or more additivestorage containers and/or hoppers for holding and/or dispensing chemicaladditives into the wastewater in the vessel or conduit of thatsubsystem, or other actuatable components such as pumps, agitators,skimmers, filters, centrifuges, heaters, settlers, electrical currentgenerators, and the like. For example, a quaternary ammonium compoundand/or emulsion breaker additive of the present disclosure may bedispensed from a chemical treatment subsystem that includes one or morechemical additive hoppers configured to dispense chemical additives intochemical treatment tanks. In some embodiments, the chemical additivecontainers, hoppers and/or other actuatable components may becommunicatively coupled to an information handling system and actuatedor otherwise controlled by signals received from the informationhandling system without the need for human intervention or actiondirected to that action.

The quaternary ammonium compound and treatment fluid may be mixed usingany suitable method and/or equipment known in the art. For example, thechemical treatment subsystem may include one or more chemical treatmenttanks, each of which may equipped with agitation devices (e.g., rotarystirring rods, paddles, blades, air nozzles, etc.). Each chemicaltreatment subsystem may also include equipment such as heaters, coolantsystems, and the like that may be used to control various conditions inthe treatment tanks.

The mechanical treatments used in the methods and systems may includeany flow shearing techniques known in the art for separating oil andwater emulsions recovered at a well site or job site. Examples of suchtechniques that may be suitable for certain embodiments of the presentdisclosure include, but are not limited to, rotating conveyance augers,pipe flow regimes, centrifuges, centrifugal spin out platforms,counterflow conveyers, skimmer arms, paddles mixers, filters, and anycombinations thereof.

The mechanical treatments used in the methods and systems may includeany additional techniques known in the art for separating oil-in-wateremulsions recovered at a well site or job site. Examples of suchtechniques that may be suitable for certain embodiments of the presentdisclosure include, but are not limited to, dissolved air flotation,skimming, filtration, reverse osmosis, settling, electric fieldapplication, electrocoagulation, and any combinations thereof. Forexample, some embodiments of the present disclosure may includefiltering undissolved solids and/or particulates from the treatmentfluid. In some embodiments, the mechanical treatments may involveperforming certain actions with the treatment fluid at one or moredifferent parameters, all of which may be varied in different mechanicaltreatments. Examples of parameters suitable for certain embodiments ofthe present disclosure include, but are not limited to, temperature,pressure, electric field strength, flow rate, centrifuge speed,residence time (e.g., time that the treatment fluid is subjected to themechanical treatment), filter material and/or pore size, and anycombination thereof.

In some embodiments, the quaternary ammonium compounds may be used incombination with mechanical means to separate or break the oil-in-wateremulsion drilling fluid for recovery of the oleaginous and/or aqueousphase. The mechanical separation may occur downhole, on the surface, orany combination thereof. In some embodiments, at least a portion of themechanical separation or breaking may be performed using a centrifuge toseparate at least a portion of the oil-in-water emulsion treatment fluidinto an oleaginous fluid and an aqueous fluid. In some embodiments, themechanical separation may include centrifuging the oil-in-water emulsiontreatment fluid at a relative centrifugal force (“ref”or “×g”) of fromabout 100 to about 3,000×g, from about 300 to about 2,000×g, from about500 to about 2,000×g, or from about 1,000 to about 2,000×g. In certainembodiments, the mechanical separation may include centrifuging theoil-in-water emulsion treatment fluid at a relative centrifugal force ofat least 500× g, at least 700× g, at least 1,000×g, or at least 1,500×g. In certain embodiments, the mechanical separation may includecentrifuging the oil-in-water emulsion treatment fluid for a period oftime of from about 1 to about 30 minutes, from about 1 to about 20minutes, from about 1 to about 10 minutes, or from about 3 to about 8minutes. In some embodiments, the mechanical separation may includecentrifuging the oil-in-water emulsion treatment fluids for at least 2minutes, at least 3 minutes, or at least 4 minutes.

In some embodiments, the methods of the present disclosure optionallymay include heating the quaternary ammonium compound and/or treatmentfluid before, during, or after the addition of the quaternary ammoniumcompound and the breaking of the emulsion of the treatment fluid. Forexample, in certain embodiments, the treatment fluid may be heated to atemperature in the range of from about 60° F. to about 150° F., fromabout 80° F. to about 150° F., or from about 120° F. to about 150° F. Insome embodiments, the treatment fluid may be heated to at least 80° F.,at least 120° F., or at least 150° F. In certain embodiments, heatingthe oil-in-water emulsion treatment fluid may increase the speed and/orthe effectiveness of the emulsion breaking and separation.

In some embodiments, at least a portion of the oil-in-water emulsiontreatment fluid may be separated into an oleaginous fluid and an aqueousfluid. In certain embodiments, the oleaginous fluid and/or aqueous fluidseparated from the oil-in-water emulsion treatment fluid may be placedin a container for disposal, storage, or transport. In some embodiment,the oleaginous fluid and/or aqueous fluid separated from theoil-in-water emulsion treatment fluid may be reused (e.g., to create newdrilling muds, roads construction material, other treatment fluids, orproducts), further treated, discharged, and/or reused in subsequentoperations (e.g., further subterranean operations at the same job sitefrom which the wastewater was recovered). In some embodiments, at leasta portion of the separated oleaginous fluid and/or aqueous fluid may becombined with other components to form a recycled treatment fluid. Incertain embodiments, the recycled treatment fluid may include awater-based mud. For example, in certain embodiments, the separatedoleaginous fluid and/or aqueous fluid may be mixed with one or moreadditional components in a mud pit and then pumped out into a drillstring or coiled tubing that is used to drill at least a portion of awellbore penetrating a subterranean formation (e.g., the samesubterranean formation from which the oil-in-water emulsion wasrecovered). In some embodiments, the recycled treatment fluid may beused to perform a treatment operation on a subterranean formation.

For example, in some embodiments, the recovered aqueous fluid and/oroleaginous fluid may be pumped into a mud pit where drilling fluids areprepared and/or held prior to use. The recovered aqueous fluid and/oroleaginous fluid may be mixed with one or more additional components inthe mud pit and then pumped out into a drill string or coiled tubingthat is used to drill at least a portion of a well bore penetrating asubterranean formation (e.g., the same subterranean formation from whichthe oil-in-water emulsion treatment fluid was recovered). In certainembodiments, the recovered aqueous fluid may be transferred from a tankto another treatment vessel such as a reverse osmosis unit, for amongother reasons, to remove any remaining oil, or to remove salts and/orother species dissolved in the water, after which the remaining freshwater may be discharged and/or reused in subsequent operations.

In some embodiments, the methods and compositions of the presentdisclosure may result in greater recovery of the oleaginous phase of theoil-in-water emulsion treatment fluid than separation methods performedwithout the methods and compositions of the present disclosure. Incertain embodiments, the methods and compositions of the presentdisclosure provide for recovery of the oleaginous phase in an amount inthe range of from about 20% to about 100%, from about 30% to about 90%,from about 40% to about 80%, from about 50% to about 80% by volume ofthe oleaginous phase of the oil-in-water emulsion treatment fluid. Incertain embodiments, the methods and compositions of the presentdisclosure provide for the recovery of at least 40%, at least 50%, or atleast 60% of the oleaginous phase of the oil-in-water emulsion treatmentfluid by volume.

In certain embodiments, the oil-in-water emulsion treatment fluids to beseparated and/or broken may be recovered from the subterranean formationin conjunction with any type of subterranean operation or treatment,including but not limited to hydraulic fracturing treatments, acidizingtreatments, and drilling operations. For example, in certainembodiments, a drilling fluid may be introduced into a subterraneanformation while drilling at least a portion of a well bore thatpenetrates a subterranean formation, and the drilling fluid may serve anumber of purposes, including but not limited to suspending andcirculating drill cuttings out of the wellbore, cooling and/orlubricating a drill bit, and the like. The recovered drilling fluid or aportion thereof then may be circulated out of the wellbore during orafter its use.

In certain embodiments, the fluids of the present disclosure may beformed at a well site where the operation or treatment is conducted,either by batch mixing or continuous (“on-the-fly”) mixing. The term“on-the-fly” is used herein to include methods of combining two or morecomponents wherein a flowing stream of one element is continuouslyintroduced into a flowing stream of at least one other component so thatthe streams are combined and mixed while continuing to flow as a singlestream as part of the on-going treatment. Such mixing can also bedescribed as “real-time” mixing. In other embodiments, the treatmentfluids of the present disclosure may be prepared, either in whole or inpart, at an offsite location and transported to the site where thetreatment or operation is conducted. In introducing a treatment fluid ofthe present disclosure into a portion of a subterranean formation, thecomponents of the treatment fluid may be mixed together at the surfaceand introduced into the formation together, or one or more componentsmay be introduced into the formation at the surface separately fromother components such that the components mix or intermingle in aportion of the formation to form a treatment fluid. In either such case,the treatment fluid is deemed to be introduced into at least a portionof the subterranean formation for purposes of the present disclosure.

The fluids used in the methods and systems of the present disclosure mayinclude any base fluid known in the art, including aqueous base fluids,non-aqueous base fluids, and any combinations thereof. Aqueous fluidsthat may be suitable for use in the methods and systems of the presentdisclosure may include water from any source. Such aqueous fluids mayinclude fresh water, salt water (e.g., water containing one or moresalts dissolved therein), brine (e.g., saturated salt water), seawater,or any combination thereof. In some embodiments of the presentdisclosure, the aqueous fluids include one or more ionic species, suchas those formed by salts dissolved in water. For example, seawaterand/or produced water may include a variety of divalent cationic speciesdissolved therein. In certain embodiments, the density of the aqueousfluid can be adjusted, among other purposes, to provide additionalparticulate transport and suspension in the compositions of the presentdisclosure. In certain embodiments, the pH of die aqueous fluid may beadjusted (e.g., by a buffer or other pH adjusting agent) to a specificlevel, which may depend on, among other factors, the types ofviscosifying agents, acids, and other additives included in the fluid.One of ordinary skill in the art, with the benefit of this disclosure,will recognize when such density and/or pH adjustments are appropriate.Examples of non-aqueous fluids that may be suitable for use in themethods and systems of the present disclosure include, but are notlimited to oils, hydrocarbons, organic liquids, and the like.

In certain embodiments, the fluids used in the methods and systems ofthe present disclosure optionally may include any number of additionaladditives. Examples of such additional additives include, but are notlimited to salts, surfactants, acids, proppant particulates, divertingagents, fluid loss control additives, gas, nitrogen, carbon dioxide,surface modifying agents, tackifying agents, foamers, corrosionInhibitors, scale inhibitors, catalysts, clay control agents, biocides,friction reducers, antifoam agents, bridging agents, flocculants, H₂Sscavengers, CO₂ scavengers, oxygen scavengers, lubricants, viscosifiers,breakers, weighting agents, relative permeability modifiers, resins,wetting agents, coating enhancement agents, filter cake removal agents,antifreeze agents (e.g., ethylene glycol), and the like. A personskilled in the art, with the benefit of this disclosure, will recognizethe types of additives that may be included in the fluids of the presentdisclosure for a particular application.

The present disclosure, in some embodiments, provides methods for usingthe fluids to carry out a variety of subterranean treatments, includingbut not limited to hydraulic fracturing treatments, acidizingtreatments, and drilling operations. In some embodiments, the fluids ofthe present disclosure may be used in treating a portion of asubterranean formation, for example, in acidizing treatments such asmatrix acidizing or fracture acidizing. In certain embodiments, a fluidmay be introduced into a subterranean formation. In some embodiments,the fluid may be introduced into a wellbore that penetrates asubterranean formation. In some embodiments, the fluid may be introducedat a pressure sufficient to create or enhance one or more fractureswithin the subterranean formation (e.g., hydraulic fracturing). Thecompositions of the present disclosure may be prepared using anysuitable method and/or equipment (e.g., blenders, mixers, stirrers,etc.) known in the art at any time prior to their use. The compositionsmay be prepared at a well site or at an offsite location.

The methods and compositions of the present disclosure may be usedduring or in conjunction with any subterranean operation. For example,the methods and/or compositions of the present disclosure may be used inthe course of a fracturing treatment. Other suitable subterraneanoperations in which the methods and/or compositions of the presentdisclosure may be used include, but are not limited to acidizingtreatments (e.g., matrix acidizing and/or fracture acidizing),hydrajetting treatments, sand control treatments (e.g., gravel packing),“frac-pack” treatments, fracturing fluids, and other operations whereemulsion breaking may be useful.

The methods and compositions of the present disclosure may also directlyor indirectly affect the various downhole or subterranean equipment andtools that can come into contact with the compositions of the presentdisclosure during operation. Such equipment and tools can includewellbore easing, wellbore liner, completion string, insert strings,drill string, coiled tubing, slickline, wireline, drill pipe, drillcollars, mud motors, downhole motors and/or pumps, surface-mountedmotors and/or pumps, centralizers, turbolizers, scratchers, floats(e.g., shoes, collars, valves, and the like), logging tools and relatedtelemetry equipment, actuators (e.g., electromechanical devices,hydromechanical devices, and the like), sliding sleeves, productionsleeves, plugs, screens, filters, flow control devices (e.g., inflowcontrol devices, autonomous inflow control devices, outflow controldevices, and the like), couplings (e.g., electro-hydraulic wet connect,dry connect, inductive coupler, and the like), control lines (e.g.,electrical, fiber optic, hydraulic, and the like), surveillance lines,drill bits and reamers, sensors or distributed sensors, downhole heatexchangers, valves and corresponding actuation devices, tool seals,packers, cement plugs, bridge plugs, and other wellbore isolationdevices or components, and the like. Any of these components can beincluded in the systems and apparatuses generally described above.

Some embodiments of the present disclosure provide methods for using thedisclosed compositions and treatment fluids to carry out a variety ofsubterranean treatments, including but not limited to, drilling. Thedrilling fluids disclosed herein may directly or indirectly affect oneor more components or pieces of equipment associated with thepreparation, delivery, recapture, recycling, reuse, and/or disposal ofthe drilling fluids. For example, and with reference to FIG. 1 , thedrilling fluids disclosed herein may directly or indirectly affect oneor more components or pieces of equipment associated with a wellboredrilling assembly 100, according to one or more embodiments. It shouldbe noted that while FIG. 1 generally depicts a land-based drillingassembly, those skilled in the art will readily recognize that theprinciples described herein are equally applicable to subsea drillingoperations that employ floating or sea-based platforms and rigs, withoutdeparting from the scope of the disclosure.

As illustrated, the drilling assembly 100 may include a drillingplatform 102 that supports a derrick 104 having a traveling block 106for raising and lowering a drill string 108. The drill string 108 mayinclude, but is not limited to, drill pipe and coiled tubing, asgenerally known to those skilled in the art. A kelly 110 supports thedrill string 108 as it is lowered through a rotary table 112. A drillbit 114 is attached to the distal end of the drill string 108 and isdriven either by a downhole motor and/or via rotation of the drillstring 108 from the well surface. As the bit 114 rotates, it creates aborehole 116 that penetrates various subterranean formations 118.

A pump 120 (e.g., a mud pump) circulates a drilling fluid 122 preparedwith the compositions disclosed herein through a feed pipe 124 and tothe kelly 110, which conveys the drilling fluid 122 downhole through theinterior of the drill string 108 and through one or more orifices in thedrill bit 114. The drilling fluid 122 is then circulated back to thesurface via an annulus 126 defined between the drill string 108 and thewalls of the borehole 116. At the surface, the recirculated or spentdrilling fluid 122 exits the annulus 126 and may be conveyed to one ormore fluid processing unit(s) 128 via an interconnecting flow line 130.After passing through the fluid processing unit(s) 128, a “cleaned”drilling fluid 122 is deposited into a nearby retention pit 132 (i.e., amud pit). While illustrated as being arranged at the outlet of thewellbore 116 via the annulus 126, those skilled in the art will readilyappreciate that the fluid processing unit(s) 128 may be arranged at anyother location in the drilling assembly 100 to facilitate its properfunction, without departing from the scope of the disclosure.

The quaternary ammonium compounds used in the methods and compositionsof the present disclosure may be added to the drilling fluid 122 via amixing hopper 134 communicably coupled to or otherwise in fluidcommunication with the retention pit 132. The mixing hopper 134 mayinclude, but is not limited to, mixers and related mixing equipmentknown to those skilled in the art. In other embodiments, however, thequaternary ammonium compounds used in the methods and compositions ofthe present disclosure may be added to the drilling fluid 122 at anyother location in the drilling assembly 100. In at least one embodiment,for example, there could be more than one retention pit 132, such asmultiple retention pits 132 in series. Moreover, the retention pit 132may be representative of one or more fluid storage facilities and/orunits where the quaternary ammonium compounds used in the methods andcompositions of the present disclosure thereof may be stored,reconditioned, and/or regulated until added to the drilling fluid 122.

As mentioned above, the drilling fluid 122 prepared with a compositiondisclosed herein may directly or indirectly affect the components andequipment of the drilling assembly 100. For example, the discloseddrilling fluid 122 may directly or indirectly affect the fluidprocessing unit(s) 128 which may include, but is not limited to, one ormore of a shaker (e.g., shale shaker), a centrifuge, a hydrocyclone, aseparator (including magnetic and electrical separators), a desilter, adesander, a filter (e.g., diatomaceous earth filters), a heat exchanger,any fluid reclamation equipment. The fluid processing unit(s) 128 mayfurther include one or more sensors, gauges, pumps, compressors, and thelike used to store, monitor, regulate, and/or recondition the drillingfluid 122.

The drilling fluid 122 prepared as disclosed herein may directly orindirectly affect the pump 120, which representatively includes anyconduits, pipelines, trucks, tubulars, and/or pipes used to fluidicallyconvey the drilling fluid 122 downhole, any pumps, compressors, ormotors (e.g., topside or downhole) used to drive the drilling fluid 122into motion, any valves or related joints used to regulate the pressureor flow rate of the drilling fluid 122, and any sensors (i.e., pressure,temperature, flow rate, etc.), gauges, and/or combinations thereof, andthe like. The disclosed drilling fluid 122 may also directly orindirectly affect the mixing hopper 134 and the retention pit 132 andtheir assorted variations.

An embodiment of the present disclosure is a method includingintroducing a quaternary ammonium compound into an oil-in-water emulsiontreatment fluid that includes an oleaginous phase and an aqueous phase;and centrifuging at least the portion of the oil-in-water emulsiontreatment fluid to separate at least a portion of the oil-in-wateremulsion treatment fluid into an oleaginous fluid and an aqueous fluid.

In one or more embodiments described above, the quaternary ammoniumcompound is non-polymeric. In one or more embodiments described above,the oil-in-water emulsion treatment fluid is a water-based mud. In oneor more embodiments described above, the method further includes forminga recycled treatment fluid including at least a portion of theoleaginous fluid or the aqueous fluid or both. In one or moreembodiments described above, the method further includes using therecycled treatment fluid to perform a treatment operation in at least aportion of a subterranean formation. In one or more embodimentsdescribed above, the quaternary ammonium compound includes a fattycarboxylic acid chain. In one or more embodiments described above, thequaternary ammonium compound is mixed with a solvent prior tointroduction into the oil-in-water emulsion treatment fluid. In one ormore embodiments described above, the method further includes, beforethe step of centrifuging, mixing the quaternary ammonium compound andthe oil-in-water emulsion treatment fluid to allow the oil-in-wateremulsion treatment fluid to at least partially separate. In one or moreembodiments described above, the oleaginous fluid includes at least 40%of the oleaginous phase of the oil-in-water emulsion treatment fluid byvolume.

In another embodiment, the present disclosure provides a methodincluding performing a treatment operation on at least a portion of asubterranean formation using an oil-in-water emulsion treatment fluidthat includes an oleaginous phase and an aqueous phase: recovering aleast a portion of the oil-in-water emulsion treatment fluid from theportion of the subterranean formation; introducing a quaternary ammoniumcompound into the recovered portion of the oil-in-water emulsiontreatment fluid at a well site; and mechanically separating at least aportion of the recovered portion of the oil-in-water emulsion treatmentfluid into an oleaginous fluid and an aqueous fluid.

In one or more embodiments described above, the mechanical separation isperformed using a centrifuge. In one or more embodiments describedabove, the method further includes forming a recycled treatment fluidincluding at least a portion of the oleaginous fluid or the aqueousfluid. In one or more embodiments described above, the method furtherincludes using the recycled treatment fluid to perform a treatmentoperation in at least a portion ofa subterranean formation. In one ormore embodiments described above, the quaternary ammonium compoundincludes a fatty carboxylic acid chain. In one or more embodimentsdescribed above, the quaternary ammonium compound is mixed with asolvent prior to introduction into the oil-in-water emulsion treatmentfluid. In one or more embodiments described above, the oleaginous fluidincludes at least 40% of the oleaginous phase of the oil-in-wateremulsion treatment fluid by volume. In one or more embodiments describedabove, the mechanical separation is performed at the well site.

In another embodiment, the present disclosure provides a methodintroducing a quaternary ammonium compound into an oil-in-water emulsiontreatment fluid; introducing a brine into the oil-in-water emulsiontreatment fluid; heating the oil-in-water emulsion treatment fluid to atleast 80° F.; and mechanically separating at least a portion of theoil-in-water emulsion treatment fluid into an oleaginous fluid and anaqueous fluid.

In one or more embodiments described above, the brine is a saturatedmonovalent brine. In one or more embodiments described above, thequaternary ammonium compound is mixed with a solvent prior tointroduction into the oil-in-water emulsion treatment fluid.

To facilitate a better understanding of the present disclosure, thefollowing examples of certain aspects of preferred embodiments aregiven. The following examples are not the only examples that could begiven according to the present disclosure and are not intended to limitthe scope of the disclosure or claims.

EXAMPLES

The following examples test the effectiveness of a series of emulsionbreaking methods and compositions.

Example 1

In this example, oil recovery tests were performed for emulsion breakingof oil-in-water emulsion field mud samples using various methods. Asshown in FIG. 2 , oil recovery results were obtained for the emulsionbreaking of four different field muds 210 (Fluids 1-IV) using differentemulsion breaking methods. The emulsion breaker of this example was aquaternary ammonium compound in isopropyl alcohol solvent (NO BLOK® C,available from Halliburton Energy Services, Inc.). The field mud samples210 (Fluids I-IV) were categorized as either unstable emulsions 220 orstable emulsions 222. The fluids were considered stable emulsions if nofluid separation (i.e., no separated brine or oil) was observed andunstable emulsions if fluid separation was observed. Fluid I 230 andFluid II 232 were unstable emulsions and Fluid III 234 and Fluid IV 236were stable emulsions.

Prior to emulsion breaking, fluid properties such as wettability and theoil-water ratio were acquired for each fluid. Wettability was determinedusing an electrical stability wettability test. The oil-water ratio wasdetermined using the retort method, i.e., by vaporizing and separatingthe fluids, and then condensing each phase. The oil/water content forFluids I-IV are listed in elements 230, 232, 234, and 236 of FIG. 2 inpercent by volume. Of the unstable emulsions, Fluid I 230 was oil wetand Fluid II 232 was water wet. Both of the stable emulsions (Fluid III234 and Fluid IV 236) were water wet.

As shown in elements 240, 242, 244, and 246 of FIG. 2 , up to fourchemical and mechanical emulsion breaking methods were tested for eachfluid. Method 1 consisted of storing 20 ml of the fluid at roomtemperature for 16 hours. Method 2 consisted of adding sufficient NOBLOK® C to 20 ml of the fluid to reach a concentration of 2% NO BLOK® Cby volume of the fluid, shaking the mixture by hand for 2 minutes, andthen storing the mixture at room temperature for 16 hours. Method 3consisted of centrifuging 20 ml of the fluid at 1,630 relativecentrifugal force (“rcf” or “g”) for 4 minutes and then storing thefluid at room temperature for 16 hours. Method 4 consisted of addingsufficient NO BLOK® C to 20 ml of the fluid to reach a concentration of2% NO BLOK® C by volume of the fluid, shaking the mixture by hand for 2minutes, centrifuging the mixture at 1,630 relative centrifugal force(“ref” or “g”) for 4 minutes, and then storing the mixture at roomtemperature for 16 hours. Fluid I was tested using methods 1 and 2, andFluids II-IV were tested using all four methods. For each fluid andmethod tested, the volume of separated oil (VI) was measured and used tocalculate the amount of separated oil in percent by volume according toequation (1):

$\begin{matrix}{{{Amount}{of}{separated}{oil}\left( {{vol}\%} \right)} = {\frac{{{oil}{volume}},{V1}}{20{ml}{of}{fluid}} \times 100}} & (1)\end{matrix}$

The amount of separated oil was then used to calculate oil recovery:

$\begin{matrix}{{{Percent}{Oil}{Recovery}} = {\frac{{Amount}{of}{separated}{oil}\left( {{vol}\%} \right)}{{emulsion}{oil}{{content}{}\left( {{vol}\%} \right)}} \times 100}} & (2)\end{matrix}$

The percent oil recovery for each emulsion breaking test is shown inelements 240. 242, 244, and 246 of FIG. 2 .

As shown, for the water wet samples (Fluids II, III, and IV), method4—the addition of NO BLOK® C(2 vol %) followed by centrifuging (1630× g,4 min) at ambient temperature-resulted in the highest overall oilrecovery. On the other hand, for the oil wet sample, the use of NO BLOK®C(2 vol %) alone was sufficient to break the emulsion.

Example 2

In this example, emulsion break feasibility testing was performed on theadditives listed in Table 1. Of these additives, NO BLOK® C, DEEPTREAT™, CFS™-461, and CFS™-684 are available from Halliburton EnergyServices, Inc.; Radiagreen MBKC-3 and Radiagreen MBKC-4 are availablefrom Oleon NV; and Silbreak™ is available from Momentive PerformanceMaterials Inc. Each additive was tested by adding a sufficient amount ofthe additive to a stable oil-in-water emulsion field mud to reach aconcentration of 2% of the surfactant by volume of the fluid, shakingthe mixture and then storing it at room temperature for 16 hours. Thepercentage of oil recovered for each test was calculated using equations(1) and (2) based on the measured separated oil volume. The percent oilrecovery for each emulsion breaker is provided below in Table 1.

TABLE 1 Percent Oil Recovery for Tested Additives at 2% by VolumeAdditive Composition Percent Oil Recovery NO BLOK ® C Quaternaryammonium ~69% oil recovery Compounds with isopropyl alcohol solventCFS ™-461 Demulsifier/wetting agent <20% oil recovery DEEP TREAT ™Dodecylbenzene sulfonate No oil recovery and sodium salt Radiagreen ™Fatty esters No oil recovery MBKC-3 Radiagreen ™ Fatty esters No oilrecovery MBKC-4 CFS ™-684 Demulsifier/wetting agent No oil recoverySilbreak ™ 327 Silicone-based demulsifier No oil recovery

As shown in Table 1, NO BLOK® C provided the highest oil recovery andwas the most effective emulsion breaker. Similar tests were performedfor the compositions in Table 1 at concentrations of 1, 3, 4, and 5% byvolume of the oil-in-water emulsion, and NO BLOK® C provided the highestoil recovery at all concentrations.

Therefore, the present disclosure is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, as thepresent disclosure may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. While numerous changes may be made bythose skilled in the art, such changes are encompassed within the spiritof the subject matter defined by the appended claims. Furthermore, nolimitations are intended to the details of construction or design hereinshown, other than as described in the claims below. It is thereforeevident that the particular illustrative embodiments disclosed above maybe altered or modified and all such variations are considered within thescope and spirit of the present disclosure. In particular, every rangeof values (e.g., “from about a to about b,” or, equivalently, “fromapproximately a to b,” or, equivalently. “from approximately a-b”)disclosed herein is to be understood as referring to the power set (theset of all subsets) of the respective range of values. The terms in theclaims have their plain, ordinary meaning unless otherwise explicitlyand clearly defined by the patentee.

What is claimed is:
 1. A method comprising: performing a treatmentoperation on at least a portion of a subterranean formation using anoil-in-water emulsion treatment fluid that comprises an oleaginous phaseand an aqueous phase; recovering at least a portion of the oil-in-wateremulsion treatment fluid from the portion of the subterranean formation;introducing a quaternary ammonium compound into the recovered portion ofthe oil-in-water emulsion treatment fluid at a well site; andmechanically separating at least a portion of the recovered portion ofthe oil-in-water emulsion treatment fluid into an oleaginous fluid andan aqueous fluid.
 2. The method of claim 1, wherein the mechanicalseparation is performed using a centrifuge.
 3. The method of claim 1,further comprising a recycled treatment fluid comprising at least aportion of the oleaginous fluid or the aqueous fluid.
 4. The method ofclaim 3, further comprising using the recycled treatment fluid toperform a treatment operation in at least a portion of a subterraneanformation.
 5. The method of claim 1, wherein the quaternary ammoniumcompound comprises a fatty carboxylic acid chain.
 6. The method of claim1, wherein the quaternary ammonium compound is mixed with a solventprior to introduction into the oil-in-water emulsion treatment fluid. 7.The method of claim 1, wherein the oleaginous fluid comprises at least40% of the oleaginous phase of the oil-in-water emulsion treatment fluidby volume.
 8. The method of claim 1, wherein the mechanical separationis performed at the well site.
 9. A method comprising: introducing aquaternary ammonium compound into an oil-in-water emulsion treatmentfluid that comprises an oleaginous phase and an aqueous phase;introducing a brine into the oil-in-water emulsion treatment fluid;heating the oil-in-water emulsion treatment fluid to at least 80° F.;and mechanically separating at least a portion of the oil-in-wateremulsion treatment fluid into an oleaginous fluid and an aqueous fluid.10. The method of claim 9, wherein the brine is a saturated monovalentbrine.
 11. The method of claim 9, wherein the quaternary ammoniumcompound is mixed with a solvent prior to introduction into theoil-in-water emulsion treatment fluid.
 12. A method comprising:introducing a quaternary ammonium compound into an oil-in-water emulsiontreatment fluid that comprises an oleaginous phase and an aqueous phase;introducing a brine into the oil-in-water emulsion treatment fluid;centrifuging at least the portion of the oil-in-water emulsion treatmentfluid to separate at least a portion of the oil-in-water emulsiontreatment fluid into an oleaginous fluid and an aqueous fluid; forming arecycled treatment fluid comprising at least a portion of the oleaginousfluid or the aqueous fluid or both; and using the recycled treatmentfluid to perform a treatment operation in at least a portion of asubterranean formation.
 13. The method of claim 12, wherein the brine isa saturated monovalent brine.
 14. The method of claim 12, wherein thequaternary ammonium compound is mixed with a solvent prior tointroduction into the oil-in-water emulsion treatment fluid.
 15. Themethod of claim 12, wherein the quaternary ammonium compound isnon-polymeric.
 16. The method of claim 12, wherein the oil-in-wateremulsion treatment fluid is a water-based mud.
 17. The method of claim12, wherein the quaternary ammonium compound comprises a fattycarboxylic acid chain.
 18. The method of claim 12, further comprising,before the step of centrifuging, mixing the quaternary ammonium compoundand the oil-in-water emulsion treatment fluid to allow the oil-in-wateremulsion treatment fluid to at least partially separate.
 19. The methodof claim 12, wherein the oleaginous fluid comprises at least 40% of theoleaginous phase of the oil-in-water emulsion treatment fluid by volume.20. The method of claim 12, wherein the centrifuging is performed at awell site.